As is well known in the field of oil and gas production, it is important to ensure hydrocarbon production fluids flowing in subsea pipeline are maintained at a temperature to prevent the formation of wax and hydrates which could interfere with fluid flow. It is recognized that there are a limited number of viable options for thermal insulation of flowlines also referred to herein as pipeline for use in deep water, subsea conditions. Any insulation must be able to withstand the high temperatures and pressures encountered by pipeline in a subsea environment. For example, the temperature of the hydrocarbon-containing fluids produced from a subterranean reservoir can range from 60 to 300° C. Subsea flowlines are under high external pressure that increases with increasing depth, e.g., up to about 5,000 psi (34.5 MPa) at water depths in the range of 10,000 ft to 12,000 ft (3050 to 3660 m).
One recognized conventional technology for thermal management of subsea pipeline is the use of “wet insulation,” in which a syntactic foam material is directly applied to the exterior of the pipeline. Wet insulation technology has the advantages of relative simplicity and low cost. However, wet insulation is not suitable for all applications. Wet insulation is often not suitable for applications having a tieback distance greater than about 12 miles (19 km). This constraint is attributed to the limitation of the wet insulation U-value. The U-value, also referred to as thermal transmittance or overall heat transfer coefficient, is a measure of the effectiveness of a material as an insulator. The lower the U-value, the better the material is as a heat insulator. Wet insulation materials generally have U-values from 1.84 to 2.89 W/(m2×K) at 3 in insulation coating thickness. It becomes increasingly difficult to achieve U-values below 2 W/(m2×K) with wet insulation as water depth increases, as the insulation material must resist the hydrostatic pressure and therefore must contain fewer voids. A thicker insulation coating may slightly increase the tieback distance; however, a thicker insulation may be damaged during offshore installation using a reel-lay installation vessel.
Another recognized conventional technology for thermal management of subsea pipeline is “pipe-in-pipe” technology, which is usually used for longer tiebacks, i.e., greater than about 12 miles. Pipe-in-pipe technology utilizes dry insulation between an inner steel pipe (flow line or flow pipe) and an outer steel pipe (carrier pipe) to protect the dry insulation from water egress and pressure. The flow line carries the hydrocarbon coming out of the well at high temperature (e.g., 60-300° C.) and at high pressure, e.g., up to about 70 MPa. The carrier pipe is designed independent of the flow line to withstand the external hydrostatic pressure that proportionately increases with depth, e.g., about 28 MPa at 2800 m depth. In deep and ultra-deep water oil and gas exploration, crude oil or gas is extracted from below the sea floor via a pipeline system to the water surface. It is important to maintain the temperature of the hot crude oil or gas flowing in the pipe above about 30-50° C. depending on the composition of the hydrocarbons (e.g., crude oil or natural gas). Maintaining a temperature in this range prevents flow restrictions or clogging due to formation of hydrates or wax, which can occur via cooling of the crude oil or gas by cold water as the hydrocarbons flow from the underwater well to the production plant on the surface. Also, if the well must be capped for maintenance or due to inclement weather, it is highly desired to keep the temperature of the hydrocarbon inside the pipe and other parts of the pipeline systems (e.g., a Christmas tree or subsea tree, risers, etc.) above precipitation temperature for as long as possible to minimize or avoid expensive and time-consuming de-clogging processes before resuming the production operation. These are the so-called flow assurance requirements for the underwater pipe-in-pipe configuration. The pipe-in-pipe configuration has been the traditional method of choice to satisfy the flow assurance requirements of the deep water exploration. This technology has the advantages of low thermal conductivity and low thermal transmittance or U-value, e.g., less than 2 W/(m2×K), and longer possible tieback distances, e.g. up to about 30 miles (48 km). However, pipe-in-pipe technology has a number of disadvantages. Because of the large amount of material and the number of parts involved, pipe-in-pipe type flowlines have higher material and fabrication costs. Installation using pipe-in-pipe technology is complex and expensive. The heavy weight of the pipeline generally requires larger installation vessels. Large hang off weight is a concern to be managed during installation. Furthermore, the pipeline may not be able to be installed with reel-lay vessels. These challenges are exacerbated as higher temperature production fluids are identified in offshore oil and gas reservoirs targeted for development, resulting from the greater temperature differential between the hot inner pipe and the cold outer pipe. In such applications, the outer diameter of the outer pipe must be increased to allow for greater insulation. The amount of pipeline that can be reeled, if at all, is limited due to the large outer diameter. Furthermore, current pipe-in-pipe designs are known to have severe limitations at depths greater than 1000 m.
There exists a need for an alternative technology for thermal management of subsea pipeline that would avoid the aforementioned problems. It would be desirable to have a technology that would include the advantages of pipe-in-pipe technology combined with easier installation and lower cost.